Invert emulsion drilling fluid containing a hygroscopic liquid and a polymeric suspending agent

ABSTRACT

An invert emulsion drilling fluid comprises: an external phase, wherein the external phase of the drilling fluid comprises a hydrocarbon liquid; an internal phase, wherein the internal phase of the drilling fluid comprises a hygroscopic liquid; and a suspending agent, wherein the suspending agent is a polymer comprising urea linkages or urea and urethane linkages. The hygroscopic liquid comprises a salt and a suitable solvent or comprises an alcohol. The drilling fluid can exclude an organophilic clay or organophilic lignite. A method of using the invert emulsion drilling fluid comprises: introducing the drilling fluid into at least a portion of a subterranean formation.

TECHNICAL FIELD

An invert emulsion drilling fluid and methods of using the drillingfluid are provided. The drilling fluid contains a hygroscopic liquid asthe internal phase and a suspending agent of a polymer comprising urealinkages. In an embodiment, the polymer also comprises urethanelinkages. In certain embodiments, the hygroscopic liquid is a saltsolution and in other embodiments, the hygroscopic liquid comprises analcohol. In an embodiment, the drilling fluid does not contain anorganophilic clay or lignite. According to some embodiments, thedrilling fluid is used in a water-sensitive formation. According toother embodiments, the water-sensitive formation is a shale formation.

SUMMARY

According to an embodiment, a method of using an invert emulsiondrilling fluid comprises: introducing the drilling fluid into at least aportion of a subterranean formation, wherein the drilling fluidcomprises: an external phase, wherein the external phase of the drillingfluid comprises a hydrocarbon liquid; an internal phase, wherein theinternal phase of the drilling fluid comprises a hygroscopic liquid; anda suspending agent, wherein the suspending agent is a polymer, whereinthe polymer comprises urea linkages.

According to another embodiment, an invert emulsion drilling fluidcomprises: an external phase, wherein the external phase of the drillingfluid comprises a hydrocarbon liquid; an internal phase, wherein theinternal phase of the drilling fluid comprises a hygroscopic liquid; anda suspending agent, wherein the suspending agent is a polymer, andwherein the polymer comprises urea linkages.

According to another embodiment, an invert emulsion drilling fluidcomprises: an external phase, wherein the external phase of the drillingfluid comprises a hydrocarbon liquid; an internal phase, wherein theinternal phase of the drilling fluid comprises a hygroscopic liquid,wherein the hygroscopic liquid is selected such that the drilling fluidhas an activity less than or equal to the amount needed to obtain ashale retention value of greater than 90%, when tested on a shaleformation sample, and wherein the drilling fluid does not contain anorganophilic clay or organophilic lignite.

DETAILED DESCRIPTION

As used herein, the words “comprise,” “have,” “include,” and allgrammatical variations thereof are each intended to have an open,non-limiting meaning that does not exclude additional elements or steps.

As used herein, a “fluid” is a substance having a continuous phase thatcan flow and conform to the outline of its container when the substanceis tested at a temperature of 71° F. (22° C.) and a pressure of oneatmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid orgas. A homogenous fluid has only one phase; whereas a heterogeneousfluid has more than one distinct phase. A colloid is an example of aheterogeneous fluid. A colloid can be: a slurry, which includes acontinuous liquid phase and undissolved solid particles as the dispersedphase; an emulsion, which includes a continuous liquid phase and atleast one dispersed phase of immiscible liquid droplets; or a foam,which includes a continuous liquid phase and a gas as the dispersedphase. As used herein, the term “emulsion” means a colloid in which anaqueous liquid is the continuous (or external) phase and a hydrocarbonliquid is the dispersed (or internal) phase. As used herein, the term“invert emulsion” means a colloid in which a hydrocarbon liquid is theexternal phase. Of course, there can be more than one internal phase ofthe emulsion or invert emulsion, but only one external phase. Forexample, there can be an external phase which is adjacent to a firstinternal phase, and the first internal phase can be adjacent to a secondinternal phase. Any of the phases of an emulsion or invert emulsion cancontain dissolved materials and/or undissolved solids.

A “gel” refers to a substance that does not easily flow and in whichshearing stresses below a certain finite value fail to produce permanentdeformation. A substance can develop gel strength. The higher the gelstrength, the more likely the substance will become a gel. Conversely,the lower the gel strength, the more likely the substance will remain ina fluid state. Although there is not a specific dividing line fordetermining whether a substance is a gel, generally, a substance with a10 minute gel strength greater than 100 lb/100 sq ft (47.88 Pa) willbecome a gel. Alternatively, generally, a substance with a 10 minute gelstrength less than 100 lb/100 sq ft (47.88 Pa) will remain in a fluidstate.

Oil and gas hydrocarbons are naturally occurring in some subterraneanformations. A subterranean formation containing oil or gas is sometimesreferred to as a reservoir. A reservoir may be located under land or offshore. In order to produce oil or gas, a wellbore is drilled into areservoir or adjacent to a reservoir.

A well can include, without limitation, an oil, gas, water, or injectionwell. As used herein, a “well” includes at least one wellbore. Awellbore can include vertical, inclined, and horizontal portions, and itcan be straight, curved, or branched. As used herein, the term“wellbore” includes any cased, and any uncased, open-hole portion of thewellbore. A near-wellbore region is the subterranean material and rockof the subterranean formation surrounding the wellbore. As used herein,a “well” also includes the near-wellbore region. The near-wellboreregion is generally considered to be the region within about 100 feet ofthe wellbore. As used herein, “into a well” means and includes into anyportion of the well, including into the wellbore or into thenear-wellbore region via the wellbore.

A portion of a wellbore may be an open hole or cased hole. In anopen-hole wellbore portion, a tubing string may be placed into thewellbore. The tubing string allows fluids to be introduced into orflowed from a remote portion of the wellbore. In a cased-hole wellboreportion, a casing is placed into the wellbore which can also contain atubing string. A wellbore can contain an annulus. Examples of an annulusinclude, but are not limited to: the space between the wellbore and theoutside of a tubing string in an open-hole wellbore; the space betweenthe wellbore and the outside of a casing in a cased-hole wellbore; andthe space between the inside of a casing and the outside of a tubingstring in a cased-hole wellbore.

A wellbore is formed using a drill bit. A drill string can be used toaid the drill bit in drilling through a subterranean formation to formthe wellbore. The drill string can include a drilling pipe. Duringdrilling operations, a drilling fluid, sometimes referred to as adrilling mud, may be circulated downwardly through the drilling pipe,and back up the annulus between the wellbore and the outside of thedrilling pipe. The drilling fluid performs various functions, such ascooling the drill bit, maintaining the desired pressure in the well, andcarrying drill cuttings upwardly through the annulus between thewellbore and the drilling pipe.

Some subterranean formations can be adversely affected by certain typesof drilling fluids. One example of a formation that can be adverselyaffected by certain types of drilling fluids is a water-sensitiveformation. One example of a drilling fluid that contains water is a“traditional” invert emulsion. A traditional invert emulsion contains ahydrocarbon liquid as the external phase and water as the internalphase. When a drilling fluid contains water, and the water comes incontact with a water-sensitive formation, then the water can adverselyaffect the subterranean formation. Some of the adverse effects caninclude swelling or sloughing of the subterranean formation, or gumboformation.

An example of a water-sensitive formation is a shale formation. Shaleformations are different from other types of formations, and there areeven differences between individual shale formations. Typically, no twoshale formations are the same. Therefore, finding ways to explore anddevelop shale gas from these formations is a challenge. However,exploration and production of shale gas as an alternative to natural gasproduced from “traditional formations” continues to receive increasedinterest due to the vast quantity of unproduced shale gas around theworld, and especially in North America. For example, it is estimatedthat there is over 3 trillion cubic feet (Tcf) of shale gas in NorthAmerica alone that is available for production.

In order to help minimize some of the adverse effects water can have ona water-sensitive formation, a traditional invert emulsion typicallycontains an internal phase of an aqueous solution of salt. Thesalt-water solution can accomplish several goals, including, loweringthe activity of the internal phase of the emulsion, maintaining asufficient hydrostatic pressure in the wellbore, and binding of thewater molecules included in the internal phase.

Activity refers to the vapor pressure of water molecules in an aqueoussolution compared with that of pure water. Activity is expressedmathematically as the ratio of two vapor pressures as follows:a_(w)=p/p_(o), where p is the vapor pressure of the solution and p_(o)is the vapor pressure of pure water. By increasing the concentration ofsalt (or other solutes) in the solution, a_(w) decreases, because thevapor pressure of the solution decreases.

Hydrostatic pressure means the force per unit area exerted by a columnof fluid at rest. Two factors that can affect the hydrostatic pressureare the density of the fluid and the depth of the fluid below theearth's surface or the surface of a body of water. Hydrostatic pressurecan be calculated using the equation: P=MW*depth*0.052, where MW is thedensity of the fluid in pounds per gallon (ppg), depth is the truevertical depth in feet, and 0.052 is a unit conversion factor to unitsof pounds per square inch (psi). A fluid overbalance is generallyperformed by placing a fluid, such as a completion brine, into theannulus at a hydrostatic pressure that exceeds the pressure exerted byfluids in the subterranean formation. In this manner, the greaterpressure on the wall of the wellbore helps to keep the formation fromcollapsing into the annular space.

A substance that can bind water molecules is often referred to as ahygroscopic substance. Hygroscopicity is the ability of a substance toattract and hold water molecules from the surrounding environmentthrough either absorption or adsorption. The hygroscopic nature of saltcan lower the activity of a salt solution and can help prevent the waterin the internal phase from flowing into and contacting thewater-sensitive formation, thus minimizing swelling or sloughing of theformation. The hygroscopic nature of some alcohols can also lower theactivity of an alcohol-water solution.

Commonly-used salts in a traditional invert emulsion include, but arenot limited to, sodium chloride, calcium chloride, calcium bromide,potassium chloride, potassium bromide, magnesium chloride, potassiumacetate, potassium formate, and magnesium sulfate, with the most commonbeing calcium chloride.

During well completion, it is common to introduce a cement compositioninto a portion of an annulus in a wellbore. Cement compositions can alsobe used in primary or secondary cementing operations, well-plugging, orgravel packing operations. During well completion, for example, a cementcomposition can be placed into and allowed to set in the annulus betweenthe wellbore and the casing in order to stabilize and secure the casingin the wellbore. By cementing the casing in the wellbore, fluids areprevented from flowing into the annulus. Consequently, oil or gas can beproduced in a controlled manner by directing the flow of oil or gasthrough the casing and into the wellhead.

A spacer fluid can be introduced into the wellbore after a wellbore isformed and before a cement composition is introduced into the well. Thespacer fluid can be circulated downwardly through a drill string ortubing string and up through the annulus. The spacer fluid functions toremove the drilling fluid from the wellbore. However, certain types ofdrilling fluids are more difficult to remove with a spacer fluidcompared to other types of drilling fluids.

In addition to salt, another common ingredient included in a traditionalinvert emulsion is an organophilic clay or organophilic lignite. As usedherein, the term “organophilic” means a substance that associates withorganic and oily surfaces and liquids and rejects aqueous systems. Asused herein, the term “organophilic clay” and “organophilic lignite”means a clay or lignite that has been coated with a fatty-acidquaternary amine to make the substance oil dispersible. Commonly-usedclays include bentonite, hectorite, attapulgite, and sepiolite. Recenttechnology, as described for example in U.S. Pat. Nos. 7,462,580 and7,488,704, issued on Dec. 9, 2008 and Feb. 10, 2009 respectively to JeffKirsner et al., introduced “clay-free” invert emulsion-based drillingfluids, which offer significant advantages over drilling fluidscontaining organophilic clays. As used herein, the term “clay-free”means a drilling fluid that does not contain any organophilic clay orlignite.

Usually, an increase in the viscosity of a base fluid, excess colloidalsolids, or both, will increase the plastic viscosity (“PV”) of a fluid.Plastic Viscosity (PV) is obtained from the Bingham-Plastic rheologicalmodel and represents the viscosity of a fluid when extrapolated toinfinite shear rate. The PV value can have an effect on the equivalentcirculating density (“ECD”) and the rate of penetration (“ROP”) of adrilling fluid. ECD is the effective circulating density exerted by afluid against the formation taking into account the flow rate andpressure drop in the annulus above the point being considered andmeasured as the difference in a drilling fluid's measured surfacedensity at the well head and the drilling fluid's equivalent circulatingdensity downhole. A low ECD is when the difference between the surfacedensity and the equivalent circulating density downhole is relativelysmall. A high PV may increase the ECD due to a greater pressure drop inthe annulus caused by internal fluid friction. A low PV may helpminimize the amount of density increase, or equivalent circulatingdensity caused by pumping the fluid. ROP is how quickly a drill bitforms a wellbore (i.e., the rate at which the drill bit penetrates asubterranean formation). A low PV may indicate that the fluid is capableof drilling rapidly because, among other things, the low viscosity offluid exiting the drill bit and the ability to use an increased flowrate. In addition to desiring a low PV value, it is also desirable tohave a low ECD and a high ROP.

Clay-free invert emulsion drilling fluids, like INNOVERT® drillingfluid, marketed by Halliburton Energy Services, Inc., for example, havebeen shown to yield high performance in drilling, including lower ECD'sand improved ROP.

There is a continuing need and thus ongoing industry-wide interest innew drilling fluids that provide improved performance while beingenvironmentally-friendly and economical.

It has been discovered that an invert emulsion drilling fluidcontaining: an internal phase comprising a hygroscopic liquid; and apolymeric suspending agent comprising urea or urea-urethane linkages canbe used in water-sensitive subterranean formations, such as a shaleformation. According to certain embodiments, the invert emulsiondrilling fluid does not contain an organophilic clay or organophiliclignite. The invert emulsion drilling fluid can be moreenvironmentally-friendly and can provide improved performance comparedto some traditional invert emulsion drilling fluids that useorganophilic lay or lignite. The invert emulsion drilling fluid caninclude a hygroscopic liquid of either a salt solution or an alcoholsolution and can have lower ECD's and a higher ROP compared to otherdrilling fluids.

Some of the desirable properties of an invert emulsion drilling fluidinclude: the invert emulsion remains stable; the invert emulsionexhibits a suitable sag factor; the invert emulsion exhibits goodrheology; the invert emulsion exhibits low fluid loss into thesubterranean formation; and the invert emulsion produces a high shaleretention value.

If any test (e.g., rheology or fluid loss) requires the step of mixing,then the invert emulsion drilling fluid is mixed according to thefollowing procedures. A known volume (in units of barrels) of theexternal phase is added to a mixing container and the container is thenplaced on a mixer base. The motor of the base is then turned on andmaintained at 11,000 revolutions per minute (rpm). Any of the followingingredients are then added to the external phase and mixed for at least5 minutes before adding the next ingredient, wherein the ingredients areadded in order of the first ingredient to last ingredient as follows: anemulsifier and an emulsifier activator; a viscosifier; a filtercakecontrol agent; the suspending agent; the internal phase; additionalviscosifiers; additive to simulate drilling solids; and a weightingagent. The ingredients can be added at a stated concentration of weightby volume of the drilling fluid, for example, in units of pounds perbarrel of the drilling fluid. It is to be understood that any mixing isperformed at ambient temperature and pressure (about 71° F. (22° C.) andabout 1 atm (0.1 MPa)).

It is also to be understood that if any test (e.g., rheology or fluidloss) requires the test be performed at a specified temperature andpossibly a specified pressure, then the temperature and pressure of thedrilling fluid is ramped up to the specified temperature and pressureafter being mixed at ambient temperature and pressure. For example, thedrilling fluid can be mixed at 71° F. (22° C.) and 1 atm (0.1 MPa) andthen placed into the testing apparatus and the temperature of thedrilling fluid can be ramped up to the specified temperature. As usedherein, the rate of ramping up the temperature is in the range of about3° F./min to about 5° F./min (about 1.67° C./min to about 2.78° C./min).After the drilling fluid is ramped up to the specified temperature andpossibly pressure, the drilling fluid is maintained at that temperatureand pressure for the duration of the testing.

A desirable property of a colloid is that the internal phase of thecolloid is uniformly distributed throughout the external phase. In thecase of an emulsion, a surfactant or an emulsifier can be used touniformly distribute the internal liquid phase throughout the externalliquid phase. In the case of a slurry, a suspending agent can be used touniformly distribute the undissolved solids throughout the externalliquid phase. As used herein, a “stable” invert emulsion drilling fluidmeans that the invert emulsion will not cream, flocculate, or coalesceand that the majority of any undissolved solids will not settle afterbeing tested according to the test conditions listed below. As usedherein, the term “cream” means at least some of the droplets of theinternal phase converge towards the surface or bottom of the emulsion(depending on the relative densities of the liquids making up theexternal and internal phases). The converged droplets maintain adiscrete droplet form. As used herein, the term “flocculate” means atleast some of the droplets of the internal phase combine to form smallaggregates in the emulsion. As used herein, the term “coalesce” means atleast some of the droplets of the internal phase combine to form largerdrops in the emulsion. Stability testing is performed according to API13I Recommended Practice for Laboratory Testing of Drilling Fluids, byplacing the drilling fluid in a stainless steel ageing cell. The ageingcell is then pressurized with nitrogen gas to prevent the fluid fromvaporizing and placed on in a hot rolling oven at a specifiedtemperature. The container is then rolled at a specified temperature fora specified time. The ageing cell is then removed from the rolling ovenand visually inspected to determine if the drilling fluid is stable.

Another desirable property of a drilling fluid is a good sag factor. Asused herein, only drilling fluids that are considered “stable” afterperforming stability testing are tested for the “sag factor” (SF) asfollows. The drilling fluid is placed into a high-temperature,high-pressure aging cell. The drilling fluid is then static aged at aspecified temperature for a specified period of time. The specificgravity (SG) of the drilling fluid is measured at the top of the fluidand at the bottom part of the fluid in the aging cell. The sag factor iscalculated using the following formula:SF=SG_(bottom)/(SG_(bottom)+SG_(top)). A sag factor of greater than 0.53indicates that the fluid has a potential to sag; therefore, a sag factorof less than or equal to 0.53 is considered to be a good sag factor.

Another desirable property of a drilling fluid is that the fluid exhibitgood rheology. Rheology is a measure of how a material deforms andflows. As used herein, the “rheology” of a drilling fluid is measuredaccording to API 13B-2 section 6.3, Recommended Practice for FieldTesting of Oil-based Drilling Fluids as follows. The drilling fluid ismixed. The drilling fluid is placed into the test cell of a rotationalviscometer, such as a FANN® Model 35 viscometer, fitted with a Bob andSleeve attachment and a spring number 1. The drilling fluid is tested atthe specified temperature and ambient pressure, about 1 atm (0.1 MPa).Rheology readings are taken at multiple rpm's, for example, at 3, 6,100, 200, 300, and 600.

A substance can develop gel strength. As used herein, the “initial gelstrength” of a drilling fluid is measured according to API 13B-2 section6.3, Recommended Practice for Field Testing of Oil-based Drilling Fluidsas follows. After the rheology testing of the substance is performed,the substance is allowed to sit in the test cell for 10 seconds (s). Themotor of the viscometer is then started at 3 rpm. The maximum deflectionon the dial reading is then multiplied by 0.48 to obtain the gelstrength at 10 s in units of lb/100 sq ft. As used herein, the “10 mingel strength” is measured as follows. After the initial gel strengthtest has been performed, the substance is allowed to sit in the testcell for 10 minutes (min). The motor of the viscometer is then startedat 3 rpm. The maximum deflection on the dial reading is multiplied by0.48 to obtain the gel strength at 10 min in units of lb/100 sq ft.

As used herein, the “plastic viscosity” of a drilling fluid is obtainedfrom the Bingham-Plastic rheological model and calculated as thedifference between the 600 rpm and 300 rpm dial readings from therheology testing, expressed in units of cP.

The yield point (“YP”) is defined as the value obtained from theBingham-Plastic rheological model when extrapolated to a shear rate ofzero. As used herein, the “yield point” of a drilling fluid iscalculated as the difference between the plastic viscosity and the 300rpm dial reading, expressed in units of lb/100 sq ft. Similarly, theyield stress or Tau zero is the stress that must be applied to amaterial to make it begin to flow (or yield), and may commonly becalculated from rheometer readings measured at rates of 3, 6, 100, 200,300 and 600 rpm. The extrapolation in this case may be performed byapplying a least-squares fit or curve fit to the Herchel-Bulkleyrheological model. A more convenient means of estimating the yieldstress is by calculating the low-shear yield point (“LSYP”) bysubtracting (2*the 3 rpm reading) from the 6 rpm reading, expressed inunits of lb/100 sq ft.

Another desirable property of a drilling fluid is a low fluid loss. Asused herein, the “fluid loss” of a drilling fluid is tested according toAPI 13B-2 section 7, Recommended Practice for Field Testing of Oil-basedDrilling Fluids procedure at a specified temperature and pressuredifferential as follows. The drilling fluid is mixed. The heating jacketof the testing apparatus is preheated to approximately 6° C. (10° F.)above the specified temperature. The drilling fluid is stirred for 5min. using a field mixer. The drilling fluid is poured into the filtercell. The testing apparatus is assembled with a filter paper insertedinto the apparatus. The drilling fluid is heated to the specifiedtemperature. When the drilling fluid reaches the specified temperature,the lower valve stem is opened and the specified pressure differentialis set. A timer is started and filtrate out of the testing apparatus iscollected in a separate volumetric container. The testing is performedfor 30 min. The total volume of filtrate collected is read. Fluid lossis measured in milliliters (mL) of fluid collected in 30 min. The totalmL of fluid loss is then multiplied by 2 to obtain the API fluid lossfor the drilling fluid in units of mL/30 min.

If the drilling fluid is to be used in a shale formation, then anotherdesirable property of the drilling fluid is a high shale retentionvalue. A shale erosion test is commonly employed to determine theability of a drilling fluid and/or the additives therein to prevent ashale formation from eroding. Such erosion, when encountered in actualfield conditions in a borehole, and as noted above, can lead to problemsranging from sloughing, to a washout, to a complete collapse of theborehole. As used herein, the “shale retention” test is performed asfollows. The drilling fluid is mixed. A portion of a specified shaleformation is crushed and ground into particles that passed through a 5mesh screen but are retained on a 10 mesh screen. 30 grams (g) of theground shale and 1 barrel (350 mL) of the drilling fluid are placed intoa pint jar (350 ml). The shale/drilling fluid mixture is then rolled ona rolling apparatus at a temperature of 150° F. (65.5° C.) for 16 hours.The drilling fluid is then screened through the 10 mesh screen and theretained solids are washed, dried, and weighed. The percent of erosionis calculated based on the weight loss of the ground shale, correctedfor the moisture content of the original sample. The shale erosion valueminus 100% corresponds to the shale retention value. A shale retentionvalue of greater than or equal to 95% indicates a high shale retentionvalue.

Any of the ingredients included in the drilling fluid can be inherentlybiodegradable. Inherent biodegradability refers to tests which allowprolonged exposure of the test substance to microorganisms. As usedherein, a substance with a biodegradation rate of >20% is regarded as“inherently primary biodegradable.” A substance with a biodegradationrate of >70% is regarded as “inherently ultimate biodegradable.” Asubstance passes the inherent biodegradability test if the substance iseither regarded as inherently primary biodegradable or inherentlyultimate biodegradable. As used herein, the “inherent biodegradability”of a substance is tested in accordance with OECD guidelines, using the302 B-1992 Zahn-Wellens test as follows. The test substance, mineralnutrients, and a relatively large amount of activated sludge in aqueousmedium is agitated and aerated at 20° C. to 25° C. in the dark or indiffuse light for up to 28 days. A blank control, containing activatedsludge and mineral nutrients but no test substance, is run in parallel.The biodegradation process is monitored by determination of DOC (orCOD(2)) in filtered samples taken at daily or other time intervals. Theratio of eliminated DOC (or COD), corrected for the blank, after eachtime interval, to the initial DOC value is expressed as the percentagebiodegradation at the sampling time. The percentage biodegradation isplotted against time to give the biodegradation curve.

According to an embodiment, a method of using an invert emulsiondrilling fluid comprises: introducing the drilling fluid into at least aportion of a subterranean formation, wherein the drilling fluidcomprises: an external phase, wherein the external phase of the drillingfluid comprises a hydrocarbon liquid; an internal phase, wherein theinternal phase of the drilling fluid comprises a hygroscopic liquid; anda suspending agent, wherein the suspending agent is a polymer, whereinthe polymer comprises urea linkages.

According to another embodiment, an invert emulsion drilling fluidcomprises: an external phase, wherein the external phase of the drillingfluid comprises a hydrocarbon liquid; an internal phase, wherein theinternal phase of the drilling fluid comprises a hygroscopic liquid; anda suspending agent, wherein the suspending agent is a polymer, andwherein the polymer comprises urea linkages.

According to another embodiment, an invert emulsion drilling fluidcomprises: an external phase, wherein the external phase of the drillingfluid comprises a hydrocarbon liquid; an internal phase, wherein theinternal phase of the drilling fluid comprises a hygroscopic liquid,wherein the hygroscopic liquid is selected such that the drilling fluidhas an activity less than or equal to the amount needed to obtain ashale retention value of greater than 90%, when tested on a shaleformation sample, and wherein the drilling fluid does not contain anorganophilic clay or organophilic lignite.

The discussion of preferred embodiments regarding the drilling fluid orany ingredient in the drilling fluid, is intended to apply to thecomposition embodiments and the method embodiments. Any reference to theunit “gallons” means U.S. gallons.

The drilling fluid is an invert emulsion. The invert emulsion includesonly one external phase and at least one internal phase. The externalphase comprises a hydrocarbon liquid. The external phase can includedissolved materials or undissolved solids. Preferably, the hydrocarbonliquid is selected from the group consisting of: a fractional distillateof crude oil; a fatty derivative of an acid, an ester, an ether, analcohol, an amine, an amide, or an imide; a saturated hydrocarbon; anunsaturated hydrocarbon; a branched hydrocarbon; a cyclic hydrocarbon;and any combination thereof. Crude oil can be separated into fractionaldistillates based on the boiling point of the fractions in the crudeoil. An example of a suitable fractional distillate of crude oil isdiesel oil. A commercially-available example of a fatty acid ester isPETROFREE® ESTER base fluid, marketed by Halliburton Energy Services,Inc. The saturated hydrocarbon can be an alkane or paraffin. Preferably,the saturated hydrocarbon is a paraffin. The paraffin can be anisoalkane (isoparaffin), a linear alkane (paraffin), or a cyclic alkane(cycloparaffin). An example of an alkane is BAROID ALKANE™ base fluid,marketed by Halliburton Energy Services, Inc. Examples of suitableparaffins include, but are not limited to: BIO-BASE 360® (an isoalkaneand n-alkane); BIO-BASE 300™ (a linear alkane); BIO-BASE 560® (a blendcontaining greater than 90% linear alkanes); and ESCAID 110™ (a mineraloil blend of mainly alkanes and cyclic alkanes). The BIO-BASE liquidsare available from Shrieve Chemical Products, Inc. in The Woodlands,Tex. The ESCAID liquid is available from ExxonMobil in Houston, Tex. Theunsaturated hydrocarbon can be an alkene, alkyne, or aromatic.Preferably, the unsaturated hydrocarbon is an alkene. The alkene can bean isoalkene, linear alkene, or cyclic alkene. The linear alkene can bea linear alpha olefin or an internal olefin. An example of a linearalpha olefin is NOVATEC™, available from M-I SWACO in Houston, Tex.Examples of internal olefins include, ENCORE® drilling fluid andACCOLADE® drilling fluid, marketed by Halliburton Energy Services, Inc.

The drilling fluid includes an internal phase. The internal phasecomprises a hygroscopic liquid. According to an embodiment, thehygroscopic liquid comprises an alcohol. Preferably, the alcohol lowersthe activity of the internal phase. According to an embodiment, thealcohol is a polyol and includes more than two hydroxyl groups.Preferably, the alcohol is water soluble. As used herein, the term“water soluble” means that more than 1 part of the substance dissolvesin 5 parts of water. Preferably, the alcohol comprises a glycerol. Theglycerol can be polyglycerol. One of the advantages to using glycerolcompared to polyglycerol is that glycerol is less expensive thanpolyglycerol. As such, the cost of using glycerol can be comparable toinvert emulsions that use salt instead of an alcohol. According to anembodiment, when the hygroscopic liquid comprises an alcohol, then thedrilling fluid does not include a water-soluble salt. According to thisembodiment, neither the hygroscopic liquid nor the water contains adissolved salt. The internal phase can be in a concentration in therange of about 0.5% to about 60% by volume of the external phase. Theinternal phase can also be in a concentration of about 15% to about 45%by volume of the external phase. If the internal phase further includeswater, then the water can be freshwater. The water can be in aconcentration in the range of about 5% to about 90% by weight of theinternal phase of the drilling fluid. If the internal phase includes thealcohol and water, then the alcohol can be in a concentration in therange of about 5% to about 90% by weight of the internal phase.

According to another embodiment, the hygroscopic liquid comprises a saltand a suitable solvent. The salt can be selected from the groupconsisting of sodium chloride, calcium chloride, calcium bromide,potassium chloride, potassium bromide, magnesium chloride, potassiumacetate, potassium formate, magnesium sulfate, and combinations thereof.The suitable solvent can be any liquid that is capable of solubilizingthe salt and forming a solution. One of skill in the art will be able toselect the suitable solvent based on the specific salt used. Accordingto an embodiment, the solvent is selected such that all of the saltdissolves in the solvent to form the hygroscopic liquid. It is to beunderstood that the internal phase can include other ingredients inaddition to the salt and the suitable solvent. The other ingredients canbe a liquid, solutes dissolved in the solvent, or undissolved solids.Examples of suitable solvents include, but are not limited to, water andan alcohol, such as methanol or ethanol. The water can be freshwater.The internal phase can be in a concentration in the range of about 0.5%to about 60% by volume of the external phase. The salt of the internalphase can be in a concentration in the range of about 2% to about 40% byweight of the internal phase. The solvent in the internal phase can bein a concentration in the range of about 60% to about 90% by weight ofthe internal phase. It is to be understood that the statedconcentrations can differ depending on the specific salt and solventthat are used, as each salt will have its own unique maximum solubilityin the particular solvent.

The drilling fluid includes a suspending agent. The suspending agent isa polymer comprising urea linkages. In an embodiment, the polymerfurther comprises urethane linkages. A polymer is a large moleculecomposed of repeating units typically connected by covalent chemicalbonds. A polymer can be formed from the polymerization reaction ofmonomers. A polymer formed from one type of monomer is called ahomopolymer. A copolymer is formed from two or more different types ofmonomers. In the polymerization reaction, the monomers are transformedinto the repeating units of a polymer. For a copolymer, the repeatingunits for each of the monomers can be arranged in various ways along thepolymer chain. For example, the repeating units can be random,alternating, periodic, or block. A polymer can also be formed in astep-wise fashion. For example, a first polymer, commonly called apre-polymer, can first be formed from the polymerization of one or moredifferent types of monomers. In the second step, the pre-polymer can bepolymerized with a final monomer(s) to form the polymer. A polymer canalso be formed in a step-wise fashion by first polymerizing twodifferent pre-polymers, and then polymerizing both of the pre-polymersto form the polymer. A polymer has an average molecular weight, which isdirectly related to the average chain length of the polymer. The averagemolecular weight for a copolymer can be expressed as follows:Avg. molecular weight=(M.W.m₁*RU m₁)+(M.W.m₂*RU m₂) . . .

where M.W.m₁ is the molecular weight of the first monomer; RU m₁ is thenumber of repeating units of the first monomer; M.W.m₂ is the molecularweight of the second monomer; and RU m₂ is the number of repeating unitsof the second monomer. For a polymer that is formed in a step-wisefashion, the molecular weight of the polymer is: the average molecularweight of the pre-polymer plus the molecular weight of the finalmonomer(s) times the number of repeating units of the final monomer(s);or the average molecular weight of both of the pre-polymers addedtogether.

A compound containing an isocyanate functional group can be referred toas an isocyanate, a compound containing an amine functional group can bereferred to as an amine, and a compound containing a hydroxyl functionalgroup can be referred to as an alcohol. A di-isocyanate is a compoundcontaining two isocyanate functional groups, a diamine is a compoundcontaining two amine functional groups, and a diol is a compoundcontaining two hydroxyl groups. A pre-polyamine is a pre-polymercontaining multiple amine functional groups, a pre-polyol is apre-polymer containing multiple hydroxyl functional groups, apre-polyisocyanate is a pre-polymer containing multiple isocyanatefunctional groups, and a pre-polyurethane is a pre-polymer formed fromthe polymerization of a first monomer containing at least one isocyanatefunctional group and a second monomer containing at least one hydroxylfunctional group and contains multiple isocyanate functional groups. Themultiple functional groups of the pre-polymer are available to bond withavailable functional groups of the final monomer or the availablefunctional groups of another pre-polymer. Any of the monomers andpre-polymers can be aliphatic or aromatic.

The suspending agent can be a polymer comprising urea linkages or ureaand urethane linkages. The following examples illustrate some of thepossible ways of forming a polymer comprising urea or urea and urethanelinkages, but are in no way meant to be all the possible ways of formingthe polymer. A polymer comprising urea linkages is formed from thecombination of a compound containing two or more isocyanate functionalgroups and a compound containing two or more amine functional groups,and can be formed by: 1) polymerizing a first monomer of di-isocyanateand a second monomer of diamine; 2) forming a pre-polyisocyanate andthen polymerizing the pre-polyisocyanate with a final monomer ofdiamine; 3) forming a pre-polyamine and then polymerizing thepre-polyamine with a monomer of di-isocyanate; or 4) forming apre-polyisocyanate and a pre-polyamine and then polymerizing both of thepre-polymers. A polymer comprising urea and urethane linkages is formedfrom the combination of a compound containing two or more isocyanatefunctional groups, a compound containing two or more amine functionalgroups, a compound containing two or more hydroxyl functional groups, ora compound containing combinations of isocyanate, amine, and hydroxylfunctional groups, and can be formed by: 1) polymerizing a monomer ofdi-isocyanate with a mixture of the monomers diol and diamine; 2)forming a pre-polyurethane and then polymerizing the pre-polyurethanewith a monomer of diamine; 3) forming a polyisocyanate, polyamine, orpolyol pre-polymer and then polymerizing the pre-polymer with theremaining monomers that contain the necessary functional groups (e.g.,forming a pre-polyamine and then polymerizing the pre-polyamine with amixture of monomers containing diol and diamine); or 4) forming morethan one pre-polymer and then polymerizing all of the pre-polymers, plusany remaining monomers that contain the necessary functional groups. Itis to be understood that any of the compounds containing the necessaryfunctional group can be a monomer or part of a pre-polymer. Of coursethe pre-polymer can include more than one of the necessary functionalgroups. It is also to be understood that the polymer and any of thepre-polymers can be natural polymers or synthetic polymers, includingresins.

Examples of suitable compounds (e.g., monomers or pre-polymers)containing two or more isocyanate functional groups include, but are notlimited to: hexamethylene-diisocyanate (HDI); toluene-diisocyanate(TDI); 2,2′-, 2,4′- and 4,4′-diisocyanatodiphenylmethane (MDI);polymethylenepolyphenyl diisocyanate (PMDI); naphthalene-diisocyanate(NDI); 1,6-diisocyanato-2,2,4-trimethylhexane; isophorone-diisocyanate;(3-isocyanato-methyl)-3,5,5-trimethyl cyclohexyl isocyanate (IPDI);tris(4-isocyanato-phenyl)-methane; phosphoric acidtris-(4-isocyanato-phenyl ester); and thiophosphoric acidtris-(4-isocyanato-phenyl ester).

Examples of suitable compounds (e.g., monomers or pre-polymers)containing two or more amine functional groups include, but are notlimited to: hydrazine; ethylenediamine; 1,2-propylenediamine;1,3-propylenediamine; 1-amino-3-methylaminopropane; 1,4-diaminobutane;N,N′-dimeth-1-ethylenediamine; 1,6-diaminohexane; 1,12-diaminododecane;2,5-diamino-2,5-dimethylhexane; trimethyl-1,6-hexane-diamine;diethylenetriamine; N,N′,N″-trimethyldiethylenetriamine;triethylenetetraamine; tetraethylenepentamine; pentaethylenehexamine;and polyethyleneimine, having average molecular weights of between 250and 10,000; dipropylenetriamine; tripropylenetetraamine;bis-(3-aminopropyl)amine; bis-(3-aminopropyl)-methylamine; piperazine;1,4-diaminocyclohexane; isophoronediamine;N-cyclohexyl-1,3-propanediamine; bis-(4-amino-cyclohexyl)methane;bis-(4-amino-3-methyl-cyclohexyl)-methane; bisaminomethyltricyclodecane(TCD-diamine); o-, m- and p-phenylenediamine;1,2-diamino-3-methylbenzene;1,3-diamino-4-methylbenzene(2,4-diaminotoluene);1,3-bisaminomethyl-4,6-dimethylbenzene; 2,4- and2,6-diamino-3,5-diethyltoluene; 1,4- and 1,6-diaminonaphthalene; 1,8-and 2,7-diaminonaphthalene; bis-(4-amino-phenyl)-methane;polymethylenepolyphenylamine; 2,2-bis-(4-aminophenyl)-propane;4,4′-oxybisaniline; 1,4-butanediol bis-(3-aminopropyl ether);2-(2-aminoethylamino)ethanol; 2,6-diamino-hexanoic acid; liquidpolybutadienes or acrylonitrile/butadiene copolymers which contain aminogroups and have average molecular weights of between 500 and 10,000; andpolyethers containing amino groups, e.g., based on polyethylene oxide,polypropylene oxide or polytetrahydrofuran and having a content ofprimary or secondary amino groups of from 0.25 to approximately 8mmol/g, preferably 1 to 8 mmol/g. Such compounds are described in: USPatent Publication No. US 2006/0052261 A1, having for named inventorsBernd Kray, Wilhelm Laufer, Patrick Galda, and Achim Fessenbecker,published on Mar. 9, 2006; and US Patent Publication No. US 2006/0058203A1, having for named inventors Willhelm Laufer, Michael Wuehr, KlausAllgower, and Patrick Galda, published on Mar. 16, 2006, each of whichis incorporated by reference in its entirety. If there is any conflictbetween a reference incorporated by reference and the presentdisclosure, the present disclosure will control.

Examples of suitable compounds (e.g., monomers or pre-polymers)containing two or more hydroxyl functional groups include, but are notlimited to: polyether polyols, polyester polyols, polycaprolactonepolyols, polycarbonate polyols, and combinations thereof.

An example of a suitable commercially-available polymer containing urealinkages (i.e., polyurea) is ADDITIN® M 10411, available from LANXESSIndia Private Limited, Business Unit—Rhein Chemie in Maharashtra, India.An example of a suitable commercially-available polymer containing ureaand urethane linkages (i.e., polyurea-urethane) is CRAYVALLAC LA-250,available from Cray Valley in Paris, France.

The suspending agent can be inherently biodegradable. In an embodiment,the suspending agent is selected such that the emulsion is stable. Forexample, any undissolved solids in the drilling fluid do not settle tothe bottom of the fluid. The suspending agent can be selected such thatthe drilling fluid has a sag factor less than or equal to 0.53. Thesuspending agent can be in at least a sufficient concentration such thatthe drilling fluid has a sag factor less than or equal to 0.53.According to another embodiment, the suspending agent is selected suchthat the drilling fluid has a 10 minute gel strength less than 40 lb/100sq ft, alternatively less than 30 lb/100 sq ft, or alternatively lessthan 20 lb/100 sq ft. The suspending agent can have a concentration suchthat the drilling fluid has a 10 minute gel strength less than 40 lb/100sq ft, alternatively less than 30 lb/100 sq ft, or alternatively lessthan 20 lb/100 sq ft. In another embodiment, the suspending agent is ina concentration of at least 1 pounds per barrel (ppb) of the drillingfluid. The suspending agent can also be in a concentration in the rangeof about 0.25 to about 15 ppb of the drilling fluid. In an embodiment,the suspending agent is in a concentration in the range of about 2 toabout 8 ppb of the drilling fluid.

The drilling fluid can further include a viscosifier. The viscosifiercan be selected from the group consisting of an inorganic viscosifier,fatty acids, and combinations thereof. Commercially-available examplesof a suitable viscosifier include, but are not limited to, RHEMOD L®,TAU-MOD®, RM-63™, and combinations thereof, marketed by HalliburtonEnergy Services, Inc. According to an embodiment, the drilling fluiddoes not contain an organophilic clay or organophilic lignite. Accordingto this embodiment, the viscosifier can be selected for use in adrilling fluid that does not contain an organophilic clay ororganophilic lignite. According to an embodiment, the viscosifier is ina concentration of at least 0.5 ppb of the drilling fluid. Theviscosifier can also be in a concentration in the range of about 0.5 toabout 20 ppb, alternatively of about 0.5 to about 10 ppb, of thedrilling fluid.

The drilling fluid can further include an emulsifier. The emulsifier canbe selected from the group consisting of tall oil-based fatty acidderivatives, vegetable oil-based derivatives, and combinations thereof.Commercially-available examples of a suitable emulsifier include, butare not limited to, EZ MUL® NT, INVERMUL® NT, LE SUPERMUL®, andcombinations thereof, marketed by Halliburton Energy Services, Inc.According to an embodiment, the emulsifier is in at least a sufficientconcentration such that the drilling fluid maintains a stable invertemulsion. According to yet another embodiment, the emulsifier is in aconcentration of at least 3 ppb of the drilling fluid. The emulsifiercan also be in a concentration in the range of about 3 to about 20 ppbof the drilling fluid.

The drilling fluid can further include an emulsifier activator. Theemulsifier activator aids the emulsifier in creating a stable invertemulsion. The emulsifier activator can be a base, such as lime.According to an embodiment, the emulsifier activator is in aconcentration of at least 0.5 ppb of the drilling fluid. The emulsifieractivator can also be in a concentration in the range of about 0.5 toabout 3 ppb of the drilling fluid.

The drilling fluid can further include a weighting agent. The weightingagent can be selected from the group consisting of barite, hematite,manganese tetroxide, calcium carbonate, and combinations thereof.According to an embodiment, the weighting agent is not an organophilicclay or organophilic lignite. Commercially-available examples of asuitable weighting agent include, but are not limited to, BAROID®,BARACARB®, BARODENSE®, MICROMAX™, and combinations thereof, marketed byHalliburton Energy Services, Inc. According to an embodiment, theweighting agent is in a concentration of at least 10 ppb of the drillingfluid. The weighting agent can also be in a concentration in the rangeof about 10 to about 500 ppb of the drilling fluid. According to anotherembodiment, the weighting agent is in at least a sufficientconcentration such that the drilling fluid has a density in the range ofabout 9 to about 20 pounds per gallon (ppg) (about 1.078 to about 2.397kilograms per liter “kg/L”). Preferably, the weighting agent is in atleast a sufficient concentration such that the drilling fluid has adensity in the range of about 9 to about 18 ppg (about 1.1 to about 2.4kg/L).

The drilling fluid can further include a fluid loss additive. The fluidloss additive can be selected from the group consisting ofmethylestyrene-co-acrylate, a substituted styrene copolymer, andcombinations thereof. Commercially-available examples of a suitablefluid loss additive include, but are not limited to, ADAPTA®, marketedby Halliburton Energy Services, Inc. According to an embodiment, thefluid loss additive is in at least a sufficient concentration such thatthe drilling fluid has an API fluid loss of less than 8 mL/30 min at atemperature of 300° F. (149° C.) and a pressure differential of 500 psi(3.4 megapascals “MPa”). The fluid loss additive can also be in at leasta sufficient concentration such that the drilling fluid has an API fluidloss of less than 5 mL/30 min at a temperature of 300° F. (149° C.) anda pressure differential of 500 psi (3.4 MPa). According to anotherembodiment, the fluid loss additive is in a concentration of at least0.5 ppb of the drilling fluid. The fluid loss additive can also be in aconcentration in the range of about 0.5 to about 10 ppb of the drillingfluid.

The drilling fluid can also include a friction reducer.Commercially-available examples of a suitable friction reducer include,but are not limited to, TORQ-TRIM® II, graphitic carbon, andcombinations thereof, marketed by Halliburton Energy Services, Inc. Thefriction reducer can be in a concentration of at least 0.5 ppb of thedrilling fluid. In an embodiment, the friction reducer is in aconcentration in the range of about 0.5 to about 5 ppb of the drillingfluid.

According to certain embodiments, the drilling fluid does not include anorganophilic clay or organophilic lignite. The drilling fluid cancontain organophilic clay, organophilic lignite, and combinationsthereof. The drilling fluid can contain the organophilic clay or ligniteat a concentration up to 1 pounds per barrel (ppb) of the drillingfluid. The drilling fluid can also contain the organophilic clay orlignite at a concentration in the range of 0 to about 20 ppb,alternatively of 0 to about 10 ppb, or alternatively from about 3 toabout 8 ppb of the drilling fluid.

According to an embodiment, the drilling fluid provides a shaleretention value of greater than 90%, in another embodiment greater than95%, when tested on a portion of a shale formation at a temperature of150° F. (65.5° C.) for 16 hours. According to another embodiment, thedrilling fluid has an activity less than or equal to the amount neededto provide a shale retention value of greater than 90%, in anotherembodiment greater than 95%, when tested on a portion of a shaleformation at a temperature of 150° F. (65.5° C.) for 16 hours. For theembodiment wherein the hygroscopic liquid contains the alcohol, then thealcohol can be selected and in at least a sufficient concentration suchthat the drilling fluid has an activity less than or equal to the amountneeded to provide a shale retention value of greater than 90%, inanother embodiment greater than 95%. For the embodiment wherein thehygroscopic liquid contains the salt and a suitable solvent, then thesalt and the suitable solvent are selected and are in at least asufficient concentration such that the drilling fluid has an activityless than or equal to the amount needed to provide a shale retentionvalue of greater than 90%, in another embodiment greater than 95%.According to these embodiments, the particular alcohol and the salt andsuitable solvent are selected and in at least a sufficient concentrationsuch that the activity of the internal phase is lowered sufficiently toprovide a shale retention value of greater than 90%, in anotherembodiment greater than 95%. The portion of the shale formation can beobtained from the Pierre shale formation (located east of the RockyMountains in the Great Plains, from North Dakota to New Mexico, U.S.A.)or the London clay formation (located southeast of England).

According to the method embodiments, the methods include the step ofintroducing the drilling fluid into at least a portion of a subterraneanformation. Preferably, the at least a portion of the subterraneanformation is a water-sensitive formation. More preferably, the at leasta portion of the subterranean formation is a shale formation. The stepof introducing the drilling fluid can be for the purpose of drilling awellbore. The drilling fluid can be in a pumpable state before andduring introduction into the subterranean formation. The well can be anoil, gas, water, or injection well. The subterranean formation caninclude an annulus. The step of introducing the drilling fluid caninclude introducing the drilling fluid into a portion of the annulus.

The methods can further include the step of introducing a spacer fluidinto the at least a portion of the subterranean formation after the stepof introducing the drilling fluid. The methods can also further includethe step of introducing a cement composition into the at least a portionof the subterranean formation. As used herein, a “cement composition” isa mixture of at least cement and water, and possibly additives. As usedherein, the term “cement” means an initially dry substance that, in thepresence of water, acts as a binder to bind other materials together. Anexample of cement is Portland cement. The step of introducing the cementcomposition can be performed after the step of introducing the drillingfluid. If the methods also include the step of introducing a spacerfluid, then the step of introducing the cement composition can beperformed after the step of introducing the spacer fluid. The step ofintroducing the cement composition can be for the purpose of at leastone of the following: well completion; foam cementing; primary orsecondary cementing operations; well-plugging; and gravel packing. Thecement composition can be in a pumpable state before and duringintroduction into the subterranean formation. The step of introducingcan include introducing the cement composition into the well. Accordingto another embodiment, the subterranean formation is penetrated by awell and the well includes an annulus. According to this otherembodiment, the step of introducing can include introducing the cementcomposition into a portion of the annulus.

The method embodiments can also include the step of allowing the cementcomposition to set. The step of allowing can be performed after the stepof introducing the cement composition into the subterranean formation.The method can include the additional steps of perforating, fracturing,or performing an acidizing treatment, after the step of allowing.

Examples

To facilitate a better understanding of the preferred embodiments, thefollowing examples of certain aspects of the preferred embodiments aregiven. The following examples are not the only examples that could begiven according to the preferred embodiments and are not intended tolimit the scope of the invention.

For the data contained in the following tables, the concentration of anyingredient in a drilling fluid is expressed as pounds per barrel of thedrilling fluid (abbreviated as “ppb”).

Each of the drilling fluids were mixed and tested according to theprocedure for the specific test as described in The Detailed Descriptionsection above. Rheology testing, initial and 10 minute gel strength,plastic viscosity, yield point, and low-shear yield point tests wereconducted at a temperature of 120° F. (48.9° C.). Stability testing wasperformed at 16 hours, and at a temperature of 250° F. (121° C.) for thedrilling fluids in group #1, #3, and #4, and at a temperature of 300° F.(149° C.) for the drilling fluids in group #2. API fluid loss testingwas conducted at a pressure differential of 500 psi (3.4 MPa), and atemperature of 250° F. (121° C.) for the drilling fluids in group #1,#3, and #4, and at a temperature of 300° F. (149° C.) for the drillingfluids in group #2. Sag factors were determined after static aging for48 hours at 250° F. (121.1° C.) for the drilling fluids in group #1, for24 hours at 250° F. (121.1° C.) for the drilling fluids in groups #3 and#4, and for either 16 hrs or 48 hrs at a temperature of 300° F. (149°C.) for the drilling fluids in group #2. Shale retention testing wasperformed on samples from the Pierre shale formation and the London clayformation at a temperature of 150° F. (65.6° C.).

Table 1 contains a list of the ingredients and their respectiveconcentrations for eight different drilling fluids. The drilling fluidsin group #1 (1A-1E) had a density of 12 ppg (1.438 kg/L) and thedrilling fluids in group #2 (2A-2C) had a density of 16 ppg (1.917kg/L). Group #1 drilling fluids had a ratio of the external phase to theinternal phase of 70:30 by volume and group #2 drilling fluids had aratio of 80:20. The internal phase for each of the drilling fluidscontained 60% glycerol and 40% fresh water by weight. The external phasefor each of the drilling fluids was ESCAID® 110 paraffin hydrocarbonliquid and is expressed in units of barrels (“bbl”). Each of thedrilling fluids also contained the following ingredients, listed at aconcentration of ppb of the drilling fluid: EZ MUL® NT emulsifier; Limeemulsifier activator; RHEMOD L® viscosifier; ADAPTA® filter controlagent; TAU-MOD® viscosifier; REV DUST drilling solids simulator; andBAROID® weighting agent. The drilling fluids also had varyingconcentrations of CRAYVALLAC LA-250 suspending agent or ADDITIN® M 10411suspending agent, listed at a concentration of ppb.

TABLE 1 Concentrations for Concentrations for Drilling Fluid #1 DrillingFluid #2 Ingredient A B C D E A B C ESCAID ® 110 0.54 0.53 0.53 0.530.51 0.48 0.47 0.46 Internal Phase 91.42 90.63 89.83 89.7 89.83 49.5248.17 47.72 EZ MUL ® NT 11 11 11 11 11 15 15 15 Lime 0.65 0.65 0.65 0.650.65 0.65 0.65 0.65 RHEMOD L ® 3 3 3 3 3 3 3 3 ADAPTA ® 4 4 4 4 4 4 4 4TAU-MOD ® 5 5 5 5 5 5 5 5 REV DUST 20 20 20 20 20 20 20 20 BAROID ®220.1 219.36 218.63 222.57 224.95 441.38 444.03 444.95 CRAYVALLAC LA-250— 3 6 — — — — — ADDITIN ® M 10411 — — — 2.5 5 — 3 4

Table 2 contains rheology data, initial and 10 min gel strength, plasticviscosity, yield point, and low-shear yield point data for the drillingfluids. As can be seen in Table 2, drilling fluids 1B-1E and 2B and 2Cexhibited comparable rheologies compared to the drilling fluids 1A and2A that did not contain a suspending agent. Moreover, the drillingfluids that contained a higher concentration of suspending agent hadslightly higher rheologies compared to the drilling fluids thatcontained a lower concentration of suspending agent.

TABLE 2 Initial 10 min Drilling Rheology rpm's Gel Gel Plastic YieldLow-shear Fluid 600 300 200 100 6 3 Strength Strength Viscosity PointYield Point 1A  59 38 31 22  7 6 6  9 21 17 5 1B  62 40 32 22  8 7 7 1022 18 6 1C  78 51 41 29 10 9 9 12 27 24 8 1D  69 42 33 23  7 6 7 11 2715 5 1E  86 54 42 29 10 9 11  19 32 22 8 2A 106 58 42 24  4 3 3  6 48 102 2B 111 63 47 30  8 7 8 10 48 15 6 2C 115 67 49 31  8 7 7 11 48 19 6

Table 3 contains stability, fluid loss, sag factor, and shale retentiondata for the drilling fluids. It should be noted that only the drillingfluids that were considered “stable” were tested for the sag factor. Ascan be seen in Table 3, in order to produce a stable fluid, theconcentration of the suspending agent may need to be increased. Each ofthe stable drilling fluids had a sag factor of less than 0.53. Thisindicates that the fluid will remain stable and any undissolved solidswill remain suspended in the fluid. Additionally, the drilling fluids 1Cand 1E provided a shale retention value of at least 97.5%. Similarly,drilling fluid 2B, having a suspending agent concentration of 3 ppb,provided a shale retention value of 98. %. This indicates that if thedrilling fluids are used in a shale formation, then it is very likelythat the drilling fluids will cause minimal erosion of the shaleformation.

TABLE 3 Shale Shale Fluid Loss Sag Factor Retention Retention Drilling(mL/ (16 hr/ Pierre London Fluid Stability 30 min) 48 hr) Shale Clay #1ASettling — —/— — — #1B Settling — —/— — — #1C Stable 2  —/0.52  100%97.5% #1D Stable 2  —/0.51 — — #1E Stable 2 —/— 99.5% — #2A Settling ——/— — — #2B Stable 3 0.52/—  98.5% — #2C Stable 2.8  —/0.527 — —

Table 4 contains a list of the ingredients and their respectiveconcentrations for four different drilling fluids. The drilling fluidsin group #3 (3A-3B) and group #4 (4A-4B) had a density of 12 ppg (1.438kg/L). These drilling fluids contained a hygroscopic solution of calciumchloride and freshwater at a concentration of 250,000 parts per million(ppm) of the water. The drilling fluids had a ratio of the externalphase to the salt solution internal phase of 70:30. The salt solution isexpressed in a concentration of ppb of the drilling fluid, which is theweight of the total solution, including the salt and the water. Theexternal phase for the drilling fluids in group #3 was ESCAID® 110paraffin hydrocarbon liquid and in group #4 was diesel, expressed inunits of barrels (“bbl”). Each of the drilling fluids also contained thefollowing ingredients, listed at a concentration of ppb of the drillingfluid: EZ MUL® NT emulsifier; Lime emulsifier activator; RHEMOD L®viscosifier; ADAPTA® fluid loss additive and BAROID® weighting agent.Some of the drilling fluids also included ADDITIN® M 10411 suspendingagent, listed at a concentration of ppb of the drilling fluid.

TABLE 4 Concentrations for Concentrations for Drilling Fluid #3 DrillingFluid #4 Ingredient A B A B ESCAID ® 110 0.54 0.53 — — Diesel — — 0.540.54 CaCl₂ Solution 114.90 113.81 116.0 114.9 EZ MUL ® NT 10 10 10 10Lime 1.5 1.5 1.5 1.5 RHEMOD L ® 3 3 3 3 ADAPTA ® 2 2 2 2 BAROID ® 224.21223.66 212.03 211.67 ADDITIN ® M 10411 — 3 — 3

Table 5 contains rheology data, initial and 10 min gel strength, plasticviscosity, yield point, and low-shear yield point data for the drillingfluids. As can be seen in Table 5, drilling fluids 3B and 4B exhibitedcomparable rheologies compared to the drilling fluids 3A and 4A that didnot contain a suspending agent. The drilling fluids in group #4containing diesel as the external phase had slightly higher valuesacross Table 5 compared to the drilling fluids in group #3 containingESCAID® 110 as the external phase.

TABLE 5 Initial 10 min Drilling Rheology rpm's Gel Gel Plastic YieldLow-shear Fluid 600 300 200 100 6 3 Strength Strength Viscosity PointYield Point #3A 31 18 13  8 2 1 2  2 13  5 0 #3B 45 26 18 12 3 2 3 10 19 7 1 #4A 55 35 27 18 6 4 5  5 20 15 2 #4B 66 42 32 22 5 4 5  9 24 18 3

Table 6 contains stability, fluid loss, and sag factor data for thedrilling fluids. It should be noted that only the drilling fluids thatwere considered “stable” were tested for the sag factor. As can be seenin Table 6, drilling fluids #3B and 4B, containing the suspending agent,had a sag factor of less than 0.53. This indicates that theses fluidswill remain stable and any undissolved solids will remain suspended inthe fluid. Moreover, each of the drilling fluids exhibited good fluidloss properties.

TABLE 6 Drilling Fluid Loss Fluid Stability (mL/30 mm) Sag Factor #3AStable 2.2 0.68 #3B Stable 2 0.52 #4A Stable 2.4 0.67 #4B Stable 2 0.52

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is, therefore, evident thatthe particular illustrative embodiments disclosed above may be alteredor modified and all such variations are considered within the scope andspirit of the present invention. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods also can “consistessentially of” or “consist of” the various components and steps.Whenever a numerical range with a lower limit and an upper limit isdisclosed, any number and any included range falling within the range isspecifically disclosed. In particular, every range of values (of theform, “from about a to about b,” or, equivalently, “from approximately ato b,” or, equivalently, “from approximately a to b”) disclosed hereinis to be understood to set forth every number and range encompassedwithin the broader range of values. Also, the terms in the claims havetheir plain, ordinary meaning unless otherwise explicitly and clearlydefined by the patentee. Moreover, the indefinite articles “a” or “an”,as used in the claims, are defined herein to mean one or more than oneof the element that it introduces. If there is any conflict in theusages of a word or term in this specification and one or more patent(s)or other documents that may be incorporated herein by reference, thedefinitions that are consistent with this specification should beadopted.

What is claimed is:
 1. An invert emulsion drilling fluid comprising: an external phase, wherein the external phase of the drilling fluid comprises a hydrocarbon liquid; an internal phase, wherein the internal phase of the drilling fluid comprises a hygroscopic liquid, wherein the hygroscopic liquid comprises an alcohol in a concentration in the range of about 5% to about 90% by weight of the internal phase; a suspending agent, wherein the suspending agent is a polymer, wherein the suspending agent is in at least a sufficient concentration such that the drilling fluid has a sag factor less than or equal to 0.53, wherein the polymer comprises urea linkages; and a friction reducer, wherein the friction reducer is in a concentration in the range of about 0.5 to about 5 pounds per barrel of the drilling fluid, wherein the drilling fluid does not comprise a water-soluble salt.
 2. The fluid according to claim 1, wherein the hydrocarbon liquid is selected from the group consisting of: a fractional distillate of crude oil; a fatty derivative of an acid, an ester, an ether, an alcohol, an amine, an amide, or an imide; a saturated hydrocarbon; an unsaturated hydrocarbon; a branched hydrocarbon; a cyclic hydrocarbon; and any combination thereof.
 3. The fluid according to claim 1, wherein the alcohol comprises a glycerol.
 4. The fluid according to claim 3, wherein the glycerol is polyglycerol.
 5. The fluid according to claim 1, wherein the internal phase is in a concentration in the range of about 0.5% to about 60% by volume of the external phase.
 6. The fluid according to claim 1, wherein the internal phase further comprises water.
 7. The fluid according to claim 1, wherein the polymer further comprises urethane linkages.
 8. The fluid according to claim 1, wherein the suspending agent is in a concentration in the range of about 0.25 to about 15 pounds per barrel of the drilling fluid.
 9. The fluid according to claim 1, wherein the drilling fluid does not contain an organophilic clay or organophilic lignite.
 10. The fluid according to claim 1, wherein the drilling fluid provides a shale retention value of greater than 90%, when tested on a portion of a shale formation at a temperature of 150° F. for 16 hours.
 11. An invert emulsion drilling fluid comprising: an external phase, wherein the external phase of the drilling fluid comprises a hydrocarbon liquid; an internal phase, wherein the internal phase of the drilling fluid comprises a hygroscopic liquid, wherein the hygroscopic liquid comprises an alcohol in a concentration in the range of about 5% to about 90% by weight of the internal phase, a friction reducer, wherein the friction reducer is in a concentration in the range of about 0.5 to about 5 pounds per barrel of the drilling fluid, and a suspending agent, wherein the suspending agent is a polymer, wherein the suspending agent is in at least a sufficient concentration such that the drilling fluid has a sag factor less than or equal to 0.53, wherein the polymer comprises urea and urethane linkages, wherein the hygroscopic liquid is selected such that the drilling fluid has an activity less than or equal to the amount needed to obtain a shale retention value of greater than 90%, when tested on a shale formation sample, and wherein the drilling fluid does not contain an organophilic clay, an organophilic lignite, and a water-soluble salt.
 12. The fluid according to claim 11, wherein the alcohol comprises a glycerol.
 13. The fluid according to claim 12, wherein the glycerol is polyglycerol.
 14. The fluid according to claim 11, wherein the internal phase is in a concentration in the range of about 0.5% to about 60% by volume of the external phase. 